Natural gas is bought and sold based on its heating value. It is the BTU content that determines the monetary value of a given volume of natural gas. This BTU value is generally expressed in decatherms (one million BTU). In the determination of total heat value of a given volume of gas, a sample of the gas is analyzed and from the composition and its heat value per unit volume is calculated. This value is generally expressed in BTU/cu ft. The typical range of transmission quality gas ranges between 1000 and 1100 BTU/cu ft. Production gas, storage facility gas, NGL, and Shale Gas can have much higher heating values up to, or even exceeding, 1500 BTU/cu ft.
There has been a long standing controversy between gas producers and gas transporters regarding entrained liquid typically present in most high BTU/cu ft gas (rich or wet gas). Transporter tariffs require essentially liquid-free gas. Hydrocarbon liquid in the gas being transported causes operational and safety problems. The practice is to separate the liquid before entering a transport (pipe) line.
The American Petroleum Institute (API) 14.1 standards (Manual of Petroleum Measurement Standards, 2006) scope does not include “wet gas” “(a term referenced by the Natural Gas industry as a gas that is at its hydrocarbon dew point temperature and/or contains entrained liquid), nor does the GPA 2166 standard (Obtaining Natural Gas Samples for Analysis by Gas Chromatography, 2005). In summary, there is no known standard which defines how to obtain a “representative sample” of a natural gas supply having entrained hydrocarbon in any form.
The liquid hydrocarbon (HC) content of a Natural gas is comprised mainly of the heavier (higher molecular weights such as propane, ethane and butane) components. As indicated by the U.S. Energy Information Administration, in discussing Natural Gas Liquids (NGLs):
“Oil and natural gas producers are increasingly targeting liquids-rich parts of supply basins due to higher crude oil prices, which influence the value of NGLs. NGL field production is growing in the United States, representing an important part of the supply picture. NGLs are extracted from the natural gas production stream in natural gas processing plants. Current elevated levels of domestic oil and gas development have pushed NGL production to an all-time high, leading to concerns over processing and distribution constraints in the coming years. Ethane, propane, butane, isobutane, and pentane are all NGLs.”, from www.eia.gov/todayinenergy/detail.cfm?id=5930
Accordingly, the heating value of NGLs can be quite high when compared to dry natural gas, and therefore NGLs or liquid hydrocarbons (HC) can have great monetary value. This is the reason that producers wish to have the liquid HC represented in the sample composition utilized for computing the BTU/cu ft content.
American Petroleum Institute (API) 14.1 standard indicates:                “2. Purpose and Scope        The purpose of this standard is to provide a comprehensive guideline for properly collecting, conditioning, and handling representative samples of natural gas that are at or above their hydrocarbon dew point . . .                    . . . This standard does not include sampling multi-phase flow (free liquid and gas) or supercritical fluids.”                        
API 14.1 standard, Appendix B section B-3 Multiphase Flow states that:                “Sampling of multiphase flow is outside the scope of this standard. Sampling of multiphase (gas and liquid) mixtures is not recommended and should be avoided if at all possible. In the multiphase flow, the ideal system would mix the gas and liquid flows uniformly and collect a sample of the true mixture flowing in the line by using a properly designed sample probe and an isokinetic sampling system. Current technology of natural gas sampling is not sufficiently advanced to accomplish this with reasonable accuracy. When sampling a multiphase liquid-gas flow, the recommended procedure is to eliminate the liquid from the sample. The liquid product that flows through the line should be determined by another method. The liquid fraction of the multiphase flow may contain water and hydrocarbons. The hydrocarbons can contribute significantly to the energy (measured in British thermal units) content of the gas and their presence in the gas line must not be overlooked.”        
The Gas Processors Association (GPA) 2166 standard's scope states that the standard is not designed for sampling Natural gas that is at, or below, its HC dew point temperature. Within the body of this standard, several references are made to avoiding liquid entrainment and condensation, due to its impact on sample composition and the calculated heat value.
The API 14.1 and GPA 2166 are the primary standards utilized by most Gas companies to guide their sampling methods. These standards specifically exclude the taking of Natural gas samples representing a combined gas and liquid, nor do they specify or advocate the taking of samples from a supercritical (dense phase) fluid stream.
Rather, the API standard specifies that, ideally, one would mix the gas and liquid flows in a multiphase stream uniformly, and collect a sample of the true mixture flowing in the line, by using a properly designed sample probe coupled with an isokinetic sampling system. However, there is currently no known technology available in the natural gas sampling arts to provide such a system which could accomplish this within acceptable parameters, particularly as to accuracy.
There have been many attempts to achieve the representative sampling of Natural gas/HC liquid mixture. Most methods use a dynamic flow isokinetic technique following homogenization via a homogenizing mixer or the like. In an ideal world, gas having perfectly mixed liquid droplets in representative suspension would be directed into the entrance port of a sample probe (isokinetic probe), without a change of velocity or direction of liquid droplets.
To accomplish this particular technique, the supply gas velocity must be known, 1) the gas velocity at the probe entrance must be maintained equal to the supply gas velocity, and 2) the probe entry design must be shaped such as not to disturb the flow pattern of the liquid droplets. This approach, even under closely controlled conditions, is not believed accurate enough for custody transfer measurement under current API standards. Therefore, it is neither a good nor a practical method for sampling wet gas on an “ongoing” basis.
Additionally, there are two other forms of liquid which may be present in the transport line other than suspended liquid droplets. One form is a liquid film which is always present when suspended droplets are flowing with the gas stream. Another form is liquid which at times flows along the bottom of the transport pipe. It is generally not known how the liquid is distributed between these three forms, and additionally, the distribution is dynamic and can be ever changing, even at the same location.
Further, measurement of only the suspended droplets generally will not generally provide an accurate indication of the total liquid present in the transport line, and thus the reason a “perfect” homogenizing mixer would be required for an accurate analysis. But such a “perfect” mixer is not believed to exist, as such a device would have to perform accurately notwithstanding varying distributions not only at one designated location, but also at various locations and with varying amounts and distributions of liquids in the fluid stream, with varying compositions as well as contaminates, flows and pressures, etc.
The Petrotech company of Kvala, Norway (hereinafter PETROTECH) utilizes an isokinetic Natural gas technique called ISOSPLIT®. The method consists of static mixing the two phases followed by dynamic isokinetic sampling of the resulting mixture. As previously stated, this technique is difficult to execute, and can produce less than desirable results. It is primarily employed at the well head. The PETROTECH U.S. Pat. No. 5,538,344 relates primarily to the positioning of a mixing body within a pipeline.
The oilfield services company Schlumberger of Sugar Land, Tex. uses a flow conditioner to attempt to homogenize or mix the two phase sample followed by independent flow measurement of the individual phases and using that information in measuring the total flow isokinetically or by measuring the pressure differential to infer and control the flow measurement. See U.S. Pat. Nos. 7,717,000 and 7,942,065.
A third company, Invensys (now Schneider Electric, based in France) uses two different flow measurement techniques to measure separately the dry gas (a differential pressure flowmeter) and the wet gas (by a Coriolis flowmeter). See U.S. Pat. No. 7,716,994.
In conclusion, the above isokinetic sampling systems are designed to insure an isokinetic fluid flow of process gas into the opening of a probe and therethrough to an external location. With such a configuration, the fluid stream velocity must be known and the fluid velocity entering the probe must be controlled, as well as having a perfectly mixed homogenized sample, which makes the technique generally impractical for typical field sampling of fluids.